Hydraulic fracturing of subterranean zones to enhance recovery of hydrocarbons is now common practice in the oil and gas industry. It has become increasingly important to estimate or discover the various properties of the targeted fracture zones, both prior to and after fracture injection. Further, hydraulic fracturing often results in massive amounts of waste-water which needs to be disposed. The waste-water can contain fracturing, stimulation, and other treatment fluids, sand, fines, and other solids from the fractured zone, excess proppant, water, brine, hydrocarbons and other components. One method of disposing of the waste-water is injection into a subterranean zone of a disposal well. Disposal can include fracturing, or re-fracturing, of the disposal well subterranean zones. As with production wells, it is useful to know or estimate various zonal properties which effect the effective reservoir volume, containment of the injected fluids, and fracture behavior after injection.
To discover such properties and behaviors, it is known in the industry to perform injection tests or other pressure tests. Such a test consists of injecting, by pumping from the surface, at a known or measured pump pressure, an injection fluid of known properties and volume into a targeted fracture zone of the reservoir. A common test is a fall-off test, in which injection is stopped and the ensuing pressure decline is measured against time. In some reservoirs, formation pressure is high enough to maintain a column of fluid in the wellbore and pressure can be monitored at the surface. Bottom-hole pressure is calculated using fluid column weight and surface pressure. Gas-injection wells and water flooding lend themselves to fall-off testing, for example. Pressure increase over time during injection can be used but is rare. The measured and calculated data is used to create pressure transient curves or plots. The equations and theory for these tests are similar to those for build-up and draw-down testing. Pressure of the zone is measured using typical techniques and equipment, such as downhole pressure sensors and communication equipment.
Standard pressure transient curve analysis has been previously used to calculate reservoir volume. However, such efforts yield no information regarding existing fractures or their behavior, shrinkage, closure, etc. The tests typically use data derived by producing a measured amount of fluid from a pressurized reservoir and observing the resultant pressure drop. Production is stopped and pressure rise is observed. By assuming certain fluid properties, an estimation of the volume of the reservoir is made by relating pressure response to produced volumes. Conventional methodologies do not provide details about closing and shrinking fractures, reservoir mobility in the surrounding rocks, or stresses in reservoir boundary layers which act to confine the propagation of the fractures during pumping.
Certain more tailored pressure transient analysis methods have been developed specifically for long-term water-injection operations. These tailored methods interpret pressure data gathered during a water injection operation, and upon its cessation, to provide certain information about size of the injection reservoir, fractures created during injection, and the extent of the water-injection horizon within the reservoir. These tailored pressure transient analysis methods for water injection operations, however, assume that the hydraulic fracture closes abruptly and does not shrink in either length or height. In reality, the fractures close more slowly and often shrink in either or both length and height, all of which alters the transient pressure response when the operation is stopped. Moreover, these tailored methods do not apply to injection and fracturing operations except long-term water-injection operations.
Another common method for estimating stimulated reservoir volume is seismic mapping. Monitored seismic signals generated by natural reservoir rock movements (passive seismic signals or micro-seismic signals) and/or seismic signals during or after fracturing are observed and recorded using a number of sensitive seismic wave receivers positioned in and about the well. These micro-seismic events are “mapped” in a virtual three-dimensional space, and the size of the created fracture network, which in very low permeability formations such as shale formations is roughly equivalent to the effective or stimulated reservoir volume, is approximated as the volume of the micro-seismic event-cloud.
Unfortunately, these methodologies do not provide details about closing and shrinking fractures, reservoir mobility in the surrounding rocks, and stress contrasts between the fractured zone and reservoir boundary layers which act to confine the propagation of the fractures during pumping. Such information would be useful in determining, among other things, a maximum pump pressure for injection to insure containment of fractures to a target zone and the degree of fracture extension beyond the target zone.